BRY Berry Corporation

Berry Corporation (bry) (NASDAQ: BRY) (“Berry” or the “Company”) announced second quarter 2024 results and declared quarterly dividends totaling $0.17 per share. The details for today’s earnings call and webcast are listed below.

Quarterly Highlights & Recent Announcements

• Produced 25,300 Boe/d, flat to first quarter; above the midpoint of 2024 annual guidance of 25,200 boe/d
• Cost reductions on pace, highlighted by 11% sequential quarter decrease in Lease Operating Expenses
• Declared second quarter dividends of $0.17 per share, including $0.12/share fixed and $0.05/share variable
• Four horizontal farm-in wells from the Uinta Basin’s prolific Uteland Butte reservoir performing above pre-drill estimates
• Reported zero recordable incidents and zero lost-time incidents for the third consecutive quarter
• Reached 60% completion of, and on schedule to meet methane emissions reduction target associated with our existing operations,

“In the second quarter, we delivered strong financial and operational results. Our teams continue to execute reliably and with excellence, and we remain on track to deliver results in line with our full year guidance provided earlier this year. We are focused on creating value by generating sustainable free cash flow with high rates of return in low capital intensity projects, optimizing our cost structure, and maintaining balance sheet strength while meeting high compliance standards,” said Fernando Araujo, Berry’s Chief Executive Officer.

He continued, “The Uinta Basin has seen increased activity and consolidation. Development activity focused on drilling horizontal wells across the basin is moving towards our existing acreage. In April 2024, we purchased a 21% working interest in four, two-to-three mile lateral wells in the Uteland Butte reservoir, which were put on production in the second quarter of 2024. These wells are adjacent to our existing operations and their results will be used to evaluate similar horizontal opportunities on our own acreage. This four-well horizontal program is exceeding pre-drill estimates. With a high working interest in almost 100,000 acres and the majority of acreage held by production in multiple trends, we are strategically positioned to develop our own acreage horizontally at an optimal pace.”

Selected Comparative Results

	Three Months Ended
	June 30, 2024				March 31, 2024				June 30, 2023
	(unaudited)(in millions, except per share amounts)
Oil, natural gas & NGL revenues(1)	$	169			$	166			$	158
Net (loss) income	$	(9	)		$	(40	)		$	26
Adjusted Net Income(2)	$	14			$	11			$	12
Cash flow from operations	$	71			$	27			$	63
Adjusted EBITDA(2)	$	74			$	69			$	69
(Loss) earnings per diluted share	$	(0.11	)		$	(0.53	)		$	0.33
Adjusted earnings per diluted share(2)	$	0.18			$	0.14			$	0.15
Adjusted free cash flow(2)	$	19			$	1			$	34
Capital expenditures	$	42			$	17			$	22
Production (mboe/d)		25.3				25.4				25.9

__________(1) Revenues do not include hedge settlements.(2) Please see “Non-GAAP Financial Measures and Reconciliations” later in this press release for reconciliation and more information on these Non-GAAP measures.

“We generated Adjusted EBITDA of $74 million in the second quarter, a 7% increase over the first quarter of 2024, with Cash Flow from Operations totaling $71 million and Adjusted Free Cash Flow of $19 million. Compared to the first quarter of 2024, lease operating expenses per boe in the second quarter were down 11% to $23.47 per boe, due primarily to lower energy costs. We continued to drive cost savings throughout the organization and prioritize debt reduction, reducing our revolver balance by nearly 30% to $36 million at the end of the second quarter. This balance was further reduced to $28 million at the end of July even after the final deferred payment from last year’s Macpherson acquisition of $20 million. In the near term, we are also looking opportunistically to refinance our notes, which mature in early 2026,” stated Mike Helm, Berry’s CFO.

Second Quarter 2024 Financial and Operating Results

Q2 2024 Compared to Q1 2024

Oil, natural gas and NGL revenues (excluding hedging settlements) for the second quarter of 2024 increased from the first quarter of 2024, driven by slightly higher oil prices. The net loss for the second quarter of 2024 included a $33 million after-tax impairment of unproved oil and gas properties driven by the implementation of California’s SB 1137 set-back regulations. The improvement of the net loss compared to the first quarter of 2024 included lower lease operating expenses, driven by lower fuel gas volumes purchased, as a result of our cost savings initiatives to reduce steam, as well as a decline in fuel prices. The second quarter of 2024 also included improved hedging results. Adjusted EBITDA and Adjusted Net Income increased in the second quarter of 2024, compared to the prior quarter. Improved working capital for the second quarter drove increased cash flows from operations and Adjusted Free Cash Flow compared to the first quarter of 2024. Capital expenditures were $42 million in the second quarter of 2024 compared to $17 million in the first quarter of 2024, with the increase driven by accelerated development in California and facilities projects, as well as the Utah farm-in development program. At June 30, 2024, the Company had liquidity of $169 million, consisting of $7 million cash and $162 million available for borrowings under its revolving credit facilities.

Q2 2024 Compared to Q2 2023

Compared to the second quarter of the prior year, oil, natural gas and NGL revenues (excluding hedging settlements) increased, which were driven by higher oil prices, offset by lower production in the second quarter of 2024. Adjusted EBITDA for the second quarter of 2024 increased 8% and Adjusted Net Income increased 21% compared to the second quarter of 2023, driven by the increased commodity revenues, a 16% decrease in general and administrative costs and a 1% decrease in lease operating expenses. Cash flow from operations increased in the second quarter of 2024 and Adjusted Free Cash Flow decreased compared to the second quarter of 2023, due to higher capital expenditures in the second quarter of 2024. Capital expenditures for the second quarter of 2024 were $42 million and increased 93% compared to the second quarter of 2023. For the second quarter of 2024, we drilled 19 wells, of which 15 are in California, plus four vertical wells in Utah, with production from our drilling activity in California outperforming expected results.

Quarterly Dividends

The Company’s Board of Directors declared dividends totaling $0.17 per share on the Company’s outstanding common stock, consisting of a fixed dividend of $0.12 per share and variable dividend of $0.05 per share based on the cumulative Adjusted Free Cash Flow results for the six months ended June 30, 2024. Both dividends are payable on August 20, 2024 to shareholders of record at the close of business on August 12, 2024.

Earnings Conference Call

The Company will host a conference call to discuss these results:

Call Date:	Friday, August 9, 2024
Call Time:	8:30 a.m. Eastern Time / 7:30 am a.m. Central Time / 5:30 a.m. Pacific Time
Join the live listen-only audio webcast at https://edge.media-server.com/mmc/p/pq98oify
or at https://bry.com/category/events

If you would like to ask a question on the live call, please preregister at any time using the following link:https://register.vevent.com/register/BI9f9fa21c30284d749f1657af20bc94dc.Once registered, you will receive the dial-in numbers and a unique PIN number. You may then dial-in or have a call back. When you dial in, you will input your PIN and be placed into the call. If you register and forget your PIN or lose your registration confirmation email, you may simply re-register and receive a new PIN.

A web based audio replay will be available shortly after the broadcast and will be archived at https://ir.bry.com/reports-resources or visit https://edge.media-server.com/mmc/p/pq98oify orhttps://bry.com/category/events

About Berry Corporation (bry)

Berry is a publicly traded (NASDAQ: BRY) western United States independent upstream energy company with a focus on onshore, low geologic risk, low decline, long-lived oil and gas reserves. We operate in two business segments: (i) exploration and production (“E&P”) and (ii) well servicing and abandonment. Our E&P assets are located in California and Utah, are characterized by high oil content and are predominantly located in rural areas with low population. Our California assets are in the San Joaquin basin (100% oil), while our Utah assets are in the Uinta basin (60% oil and 40% gas). We operate our well servicing and abandonment segment in California. More information can be found at the Company’s website at bry.com.

Forward-Looking Statements

The information in this press release includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. You can typically identify forward-looking statements by words such as aim, anticipate, achievable, believe, budget, continue, could, effort, estimate, expect, forecast, goal, guidance, intend, likely, may, might, objective, outlook, plan, potential, predict, project, seek, should, target, will or would and other similar words that reflect the prospective nature of events or outcomes. All statements, other than statements of historical facts, included in this press release that address plans, activities, events, objectives, goals, strategies, or developments that the Company expects, believes or anticipates will or may occur in the future, such as those regarding our financial position; liquidity; our ability to refinance our indebtedness; cash flows (including, but not limited to, Adjusted Free Cash Flow); financial and operating results; capital program and development and production plans; operations and business strategy; potential acquisition and other strategic opportunities; reserves; hedging activities; capital expenditures; return of capital; our shareholder return model and the payment of future dividends; future repurchases of stock or debt; capital investments; our ESG strategy and the initiation of new projects or business in connection therewith, recovery factors; and other guidance are forward-looking statements. Actual results may differ from anticipated results, sometimes materially, and reported results should not be considered an indication of future performance. For any such forward-looking statement that includes a statement of the assumptions or bases underlying such forward-looking statement, we caution that while we believe such assumptions or bases to be reasonable and make them in good faith, assumed facts or bases always vary from actual results, sometimes materially.

Berry cautions you that these forward-looking statements are subject to all of the risks and uncertainties incident to acquisition transactions and the exploration for and development, production, gathering and sale of natural gas, NGLs and oil most of which are difficult to predict and many of which are beyond Berry’s control. These risks include, but are not limited to, commodity price volatility; legislative and regulatory actions that may prevent, delay or otherwise restrict our ability to drill and develop our assets, including with respect to existing and/or new requirements in the regulatory approval and permitting process; legislative and regulatory initiatives in California or our other areas of operation addressing climate change or other environmental concerns; investment in and development of competing or alternative energy sources; drilling, production and other operating risks; effects of competition; uncertainties inherent in estimating natural gas and oil reserves and in projecting future rates of production; our ability to replace our reserves through exploration and development activities or strategic transactions; cash flow and access to capital; the timing and funding of development expenditures; environmental, health and safety risks; effects of hedging arrangements; potential shut-ins of production due to lack of downstream demand or storage capacity; disruptions to, capacity constraints in, or other limitations on the third-party transportation and market takeaway infrastructure (including pipeline systems) that deliver our oil and natural gas and other processing and transportation considerations; the ability to effectively deploy our ESG strategy and risks associated with initiating new projects or business in connection therewith; our ability to successfully integrate the Macpherson assets into our operations; we fail to identify risks or liabilities related to Macpherson, its operations or assets; our inability to achieve anticipated synergies; our ability to successfully execute other strategic bolt-on acquisitions; overall domestic and global political and economic conditions; inflation levels, including increased interest rates and volatility in financial markets and banking; changes in tax laws and the other risks described under the heading “Item 1A. Risk Factors” in the Company’s Annual Report on Form 10-K for the year ended December 31, 2023 and subsequent filings with the SEC.

Any forward-looking statement speaks only as of the date on which such statement is made, and we undertake no responsibility to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise except as required by applicable law. Investors are urged to consider carefully the disclosure in our filings with the Securities and Exchange Commission, available from us at via our website or via the Investor Relations contact below, or from the SEC’s website at www.sec.gov.

Tables Following

The financial information and certain other information presented have been rounded to the nearest whole number or the nearest decimal. Therefore, the sum of the numbers in a column may not conform exactly to the total figure given for that column in certain tables. In addition, certain percentages presented here reflect calculations based upon the underlying information prior to rounding and, accordingly, may not conform exactly to the percentages that would be derived if the relevant calculations were based upon the rounded numbers, or may not sum due to rounding.

SUMMARY OF RESULTS

	Three Months Ended
	June 30, 2024				March 31, 2024				June 30, 2023
	(unaudited)($ and shares in thousands, except per share amounts)
Consolidated Statement of Operations Data:
Revenues and other:
Oil, natural gas and natural gas liquids sales	$	168,781			$	166,318			$	157,703
Service revenue		31,155				31,683				47,674
Electricity sales		3,691				4,243				3,078
(Losses) gains on oil and gas sales derivatives		(5,844	)			(71,200	)			20,871
Other revenues		36				67				36
Total revenues and other		197,819				131,111				229,362
Expenses and other:
Lease operating expenses		53,989				60,697				54,707
Cost of services		25,021				27,304				37,083
Electricity generation expenses		552				1,093				1,273
Transportation expenses		1,039				1,059				1,096
Acquisition costs		1,394				2,617				972
General and administrative expenses		18,881				20,234				22,488
Depreciation, depletion and amortization		42,843				42,831				39,755
Impairment of oil and gas properties		43,980				—				—
Taxes, other than income taxes		12,674				15,689				13,707
Losses on natural gas purchase derivatives		2,642				4,481				14,024
Other operating (income)		(3,204	)			(133	)			(1,033	)
Total expenses and other		199,811				175,872				184,072
Other expenses:
Interest expense		(10,050	)			(9,140	)			(8,794	)
Other, net		(53	)			(83	)			(110	)
Total other expenses		(10,103	)			(9,223	)			(8,904	)
(Loss) income before income taxes		(12,095	)			(53,984	)			36,386
Income tax (benefit) expense		(3,326	)			(13,900	)			10,616
Net (loss) income	$	(8,769	)		$	(40,084	)		$	25,770
Net (loss) income per share:
Basic	$	(0.11	)		$	(0.53	)		$	0.34
Diluted	$	(0.11	)		$	(0.53	)		$	0.33
Weighted-average shares of common stock outstanding - basic		76,939				76,254				76,721
Weighted-average shares of common stock outstanding - diluted		76,939				76,254				79,285
Adjusted Net Income(1)	$	14,155			$	10,910			$	11,666
Weighted-average shares of common stock outstanding - diluted		77,161				77,373				79,285
Diluted earnings per share on Adjusted Net Income(1)	$	0.18			$	0.14			$	0.15
	Three Months Ended
	June 30, 2024				March 31, 2024				June 30, 2023
	(unaudited)($ and shares in thousands, except per share amounts)
Adjusted EBITDA(1)	$	74,329			$	68,534			$	69,055
Adjusted Free Cash Flow(1)	$	19,333			$	1,104			$	33,774
Adjusted General and Administrative Expenses(1)	$	17,038			$	18,943			$	19,109
Effective Tax Rate		28	%			26	%			29	%
Cash Flow Data:
Net cash provided by operating activities	$	70,891			$	27,273			$	62,538
Net cash used in investing activities	$	(42,486	)		$	(18,661	)		$	(27,961	)
Net cash used in financing activities	$	(25,174	)		$	(9,990	)		$	(40,128	)

__________(1) See further discussion and reconciliation in “Non-GAAP Financial Measures and Reconciliations”.

	June 30, 2024			December 31, 2023
	(unaudited)($ and shares in thousands)
Balance Sheet Data:
Total current assets	$	127,489		$	140,800
Total property, plant and equipment, net	$	1,349,593		$	1,406,612
Total current liabilities	$	204,545		$	223,182
Long-term debt	$	433,656		$	427,993
Total stockholders' equity	$	672,960		$	757,976
Outstanding common stock shares as of		76,939			75,667

The following table represents selected financial information for the periods presented regarding the Company's business segments on a stand-alone basis and the consolidation and elimination entries necessary to arrive at the financial information for the Company on a consolidated basis.

	Three Months EndedJune 30, 2024
	E&P			Well Servicing and Abandonment			Corporate/Eliminations				ConsolidatedCompany
	(unaudited)(in thousands)
Revenues(1)	$	172,508		$	36,680		$	(5,525	)		$	203,663
Net (loss) income before income taxes	$	13,860		$	1,122		$	(27,077	)		$	(12,095	)
Capital expenditures	$	41,735		$	468		$	122			$	42,325
Total assets	$	1,547,334		$	63,329		$	(77,754	)		$	1,532,909

	Three Months EndedMarch 31, 2024
	E&P				Well Servicing and Abandonment				Corporate/Eliminations				ConsolidatedCompany
	(unaudited)(in thousands)
Revenues(1)	$	170,628			$	35,468			$	(3,785	)		$	202,311
Net income (loss) before income taxes	$	(24,836	)		$	(1,269	)		$	(27,879	)		$	(53,984	)
Capital expenditures	$	15,417			$	1,332			$	187			$	16,936
Total assets	$	1,625,178			$	65,948			$	(115,610	)		$	1,575,516

	Three Months EndedJune 30, 2023
	E&P			Well Servicing andAbandonment			Corporate/Eliminations				ConsolidatedCompany
	(unaudited)(in thousands)
Revenues(1)	$	160,817		$	49,299		$	(1,625	)		$	208,491
Net income (loss) before income taxes	$	62,012		$	4,836		$	(30,462	)		$	36,386
Capital expenditures	$	19,625		$	1,334		$	936			$	21,895
Total assets	$	1,457,694		$	72,653		$	(8,644	)		$	1,521,703

__________(1) These revenues do not include hedge settlements.

COMMODITY PRICING

	Three Months Ended
	June 30, 2024				March 31, 2024				June 30, 2023
Weighted Average Realized Prices
Oil without hedge ($/bbl)	$	78.18			$	75.31			$	70.68
Effects of scheduled derivative settlements ($/bbl)		(4.60	)			(2.17	)			(0.81	)
Oil with hedge ($/bbl)	$	73.58			$	73.14			$	69.87
Natural gas ($/mcf)	$	1.78			$	3.76			$	2.87
NGLs ($/bbl)	$	24.46			$	29.60			$	22.16
Purchased Natural Gas
Purchase price, before the effects of derivative settlements ($/mmbtu)	$	2.26			$	3.99			$	3.44
Effects of derivative settlements ($/mmbtu)		2.04				0.92				2.20
Purchase price, after the effects of derivative settlements($/mmbtu)	$	4.30			$	4.91			$	5.64
Index Prices
Brent oil ($/bbl)	$	85.03			$	81.76			$	77.73
WTI oil ($/bbl)	$	80.60			$	77.02			$	73.73
Natural gas ($/mmbtu) – SoCal Gas city-gate(1)	$	1.86			$	4.21			$	5.66
Natural gas ($/mmbtu) - Northwest, Rocky Mountains(2)	$	1.40			$	3.41			$	2.85
Henry Hub natural gas ($/mmbtu)(2)	$	2.07			$	2.15			$	2.16

__________

(1) The natural gas we purchase to generate steam and electricity is primarily based on Rockies price indexes, including transportation charges, as we currently purchase a substantial majority of our gas needs from the Rockies, with the balance purchased in California. SoCal Gas city-gate Index is the relevant index used only for the portion of gas purchases in California.(2) Most of our gas purchases and gas sales in the Rockies are predicated on the Northwest, Rocky Mountains index, and to a lesser extent based on Henry Hub.

Natural gas prices and differentials are strongly affected by local market fundamentals, availability of transportation capacity from producing areas and seasonal impacts. The Company's key exposure to gas prices is in costs. The Company purchases substantially more natural gas for California steamfloods and cogeneration facilities than what is produced and sold in the Rockies. The Company purchases most of its gas in the Rockies and transports it to its California operations using the Kern River pipeline capacity. The Company buys approximately 48,000 mmbtu/d in the Rockies, and the remainder comes from California markets. The volume purchased in California fluctuates and averaged 2,000 mmbtu/d in the second quarter of 2024, 5,000 mmbtu/d in the first quarter of 2024 and 6,000 mmbtu/d in the second quarter of 2023. The natural gas purchased in the Rockies is shipped to operations in California to help limit exposure to California fuel gas purchase price fluctuations. The Company strives to further minimize the variability of fuel gas costs for steam operations by hedging a significant portion of gas purchases. Additionally, the negative impact of higher gas prices on California operating expenses is partially offset by higher gas sales for the gas produced and sold in the Rockies. The Kern capacity allows us to purchase and sell natural gas at the same pricing indices.

CURRENT HEDGING SUMMARY

As of August 6, 2024, we had the following crude oil production and gas purchases hedges.

		Q3 2024			Q4 2024			FY 2025			FY 2026			FY 2027			FY 2028			FY 2029
Brent - Crude Oil production
Swaps
Hedged volume (bbls)			1,481,749			1,438,656			4,951,125			2,633,268			3,056,000			2,378,000			724,000
Weighted-average price ($/bbl)		$	76.88		$	76.93		$	76.07		$	71.76		$	70.66		$	68.36		$	67.44
Sold Calls(1)
Hedged volume (bbls)			92,000			92,000			296,127			1,251,500			318,500			—			—
Weighted-average price ($/bbl)		$	105.00		$	105.00		$	88.69		$	85.53		$	80.03		$	—		$	—
Purchased Puts (net)(2)
Hedged volume (bbls)			322,000			322,000			—			—			—			—			—
Weighted-average price ($/bbl)		$	50.00		$	50.00		$	—		$	—		$	—		$	—		$	—
Purchased Puts (net)(2)
Hedged volume (bbls)			—			—			296,127			1,251,500			318,500			—			—
Weighted-average price ($/bbl)		$	—		$	—		$	60.00		$	60.00		$	65.00		$	—		$	—
Sold Puts (net)(2)
Hedged volume (bbls)			46,000			46,000			—			—			—			—			—
Weighted-average price ($/bbl)		$	40.00		$	40.00		$	—		$	—		$	—		$	—		$	—
NWPL - Natural Gas purchases(3)
Swaps
Hedged volume (mmbtu)			3,680,000			3,680,000			13,380,000			3,040,000			—			—			—
Weighted-average price ($/mmbtu)		$	3.96		$	3.96		$	4.27		$	4.26		$	—		$	—		$	—

__________(1) Purchased calls and sold calls with the same strike price have been presented on a net basis.(2) Purchased puts and sold puts with the same strike price have been presented on a net basis.(3) The term “NWPL” is defined as Northwest Rocky Mountain Pipeline.

(LOSSES) GAINS ON DERIVATIVES

A summary of gains and losses on the derivatives included on the statements of operations is presented below:

	Three Months Ended
	June 30,2024				March 31,2024				June 30,2023
	(unaudited)(in thousands)
Realized (losses) on commodity derivatives:
Realized (losses) on oil sales derivatives	$	(9,801	)		$	(4,682	)		$	(1,770	)
Realized (losses) on natural gas purchase derivatives		(9,314	)			(4,412	)			(10,754	)
Total realized (losses) on derivatives	$	(19,115	)		$	(9,094	)		$	(12,524	)
Unrealized gains (losses) on commodity derivatives:
Unrealized gains (losses) on oil sales derivatives	$	3,957			$	(66,518	)		$	22,641
Unrealized gains (losses) on natural gas purchase derivatives		6,672				(69	)			(3,270	)
Total unrealized gains (losses) on derivatives	$	10,629			$	(66,587	)		$	19,371
Total (losses) gains on derivatives	$	(8,486	)		$	(75,681	)		$	6,847

E&P FIELD OPERATIONS

	Three Months Ended
	June 30, 2024			March 31, 2024			June 30, 2023
	(unaudited)($ in per boe amounts)
Expenses from field operations
Lease operating expenses	$	23.47		$	26.28		$	23.17
Electricity generation expenses		0.24			0.47			0.54
Transportation expenses		0.45			0.46			0.46
Total	$	24.16		$	27.21		$	24.17
Cash settlements paid for gas purchase hedges	$	4.05		$	1.91		$	4.56
E&P non-production revenues
Electricity sales	$	1.60		$	1.84		$	1.30
Transportation sales		0.02			0.03			0.02
Total	$	1.62		$	1.87		$	1.32

Overall, management assesses the efficiency of the Company's E&P field operations by considering core E&P operating expenses together with cogeneration, marketing and transportation activities. In particular, a core component of E&P operations in California is steam, which is used to lift heavy oil to the surface. The Company operates several cogeneration facilities to produce some of the steam needed in operations. In comparing the cost effectiveness of cogeneration plants against other sources of steam in operations, management considers the cost of operating the cogeneration plants, including the cost of the natural gas purchased to operate the facilities, against the value of the steam and electricity used in E&P field operations and the revenues received from sales of excess electricity to the grid. The Company strives to minimize the variability of its fuel gas costs for California steam operations with natural gas purchase hedges. Consequently, the efficiency of E&P field operations are impacted by the cash settlements received or paid from these derivatives. The Company also has contracts for the transportation of fuel gas from the Rockies, which has historically been cheaper than the California markets. With respect to transportation and marketing, management also considers opportunistic sales of incremental capacity in assessing the overall efficiencies of E&P operations.

Lease operating expenses include fuel, labor, field office, vehicle, supervision, maintenance, tools and supplies, and workover expenses. Electricity generation expenses include the portion of fuel, labor, maintenance, and tools and supplies from two of the Company's cogeneration facilities allocated to electricity generation expense; the remaining cogeneration expenses are included in lease operating expense. Transportation expenses relate to costs to transport the oil and gas that is produced within the Company's properties or moved to the market. Marketing expenses mainly relate to natural gas purchased from third parties that moves through gathering and processing systems and then is sold to third parties. Electricity revenue is from the sale of excess electricity from two of the Company's cogeneration facilities to a California utility company under long-term contracts at market prices. These cogeneration facilities are sized to satisfy the steam needs in their respective fields, but the corresponding electricity produced is more than the electricity that is currently required for the operations in those fields. Transportation sales relate to water and other liquids that transport on the Company's systems on behalf of third parties and marketing revenues represent sales of natural gas purchased from and sold to third parties.

PRODUCTION STATISTICS

	Three Months Ended
	June 30, 2024		March 31, 2024		June 30, 2023
Net Oil, Natural Gas and NGLs Production Per Day(1):
Oil (mbbl/d)
California	21.1		21.3		20.8
Utah	2.3		2.5		3.2
Total oil	23.4		23.8		24.0
Natural gas (mmcf/d)
California	—		—		—
Utah	8.9		7.9		9.2
Total natural gas	8.9		7.9		9.2
NGLs (mbbl/d)
California	—		—		—
Utah	0.4		0.3		0.4
Total NGLs	0.4		0.3		0.4
Total Production (mboe/d)(2)	25.3		25.4		25.9

__________(1) Production represents volumes sold during the period. We also consume a portion of the natural gas we produce on lease to extract oil and gas.(2) Natural gas volumes have been converted to boe based on energy content of six mcf of gas to one bbl of oil. Barrels of oil equivalence does not necessarily result in price equivalence. The price of natural gas on a barrel of oil equivalent basis is currently substantially lower than the corresponding price for oil and has been similarly lower for a number of years. For example, in the three months ended June 30, 2024, the average prices of Brent oil and Henry Hub natural gas were $85.03 per bbl and $2.07 per mmbtu respectively.

CAPITAL EXPENDITURES

	Three Months Ended
	June 30, 2024			March 31, 2024			June 30, 2023
				(unaudited)(in thousands)
Capital expenditures (1)(2)	$	42,325		$	16,936		$	21,895

__________(1) Capital expenditures include capitalized overhead and interest and excludes acquisitions and asset retirement spending.(2) Capital expenditures for the three months ended June 30, 2024, March 31, 2024 and June 30, 2023 included less than $1 million, $1 million and $1 million, respectively, related to the well servicing and abandonment business.

NON-GAAP FINANCIAL MEASURES AND RECONCILIATIONS

Adjusted Net Income (Loss) is not a measure of net income (loss), Adjusted Free Cash Flow is not a measure of cash flow, and Adjusted EBITDA is not a measure of either net income (loss) or cash flow, in all cases, as determined by GAAP. Adjusted EBITDA, Adjusted Free Cash Flow, Adjusted Net Income (Loss) and Adjusted General and Administrative Expenses are supplemental non-GAAP financial measures used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies.

We define Adjusted EBITDA as earnings before interest expense; income taxes; depreciation, depletion, and amortization; derivative gains or losses net of cash received or paid for scheduled derivative settlements; impairments; stock compensation expense; and unusual and infrequent items. Our management believes Adjusted EBITDA provides useful information in assessing our financial condition, results of operations and cash flows and is widely used by the industry and the investment community. The measure also allows our management to more effectively evaluate our operating performance and compare the results between periods without regard to our financing methods or capital structure. We also use Adjusted EBITDA in planning our capital expenditure allocation to sustain production levels and to determine our strategic hedging needs aside from the hedging requirements of the 2021 RBL Facility.

We define Adjusted Free Cash Flow, which is a non-GAAP financial measure, as cash flow from operations less regular fixed dividends and capital expenditures. In 2024, we updated the definition of Adjusted Free Cash Flow, a non-GAAP measure, as cash flow from operations less regular fixed dividends and capital expenditures. This update better aligns with the full capital expenditure requirements of the Company. For 2023, Adjusted Free Cash Flow was defined as cash flow from operations less regular fixed dividends and maintenance capital. Management believes Adjusted Free Cash Flow may be useful in an investor analysis of our ability to generate cash from operating activities from our existing oil and gas asset base after maintaining the existing production volumes of that asset base to return capital to stockholders, fund further business expansion through acquisitions or investments in our existing asset base to increase production volumes and pay other non-discretionary expenses. Management also uses Adjusted Free Cash Flow as the primary metric to plan for future growth.

Adjusted Free Cash Flow does not represent the total increase or decrease in our cash balance, and it should not be inferred that the entire amount of Adjusted Free Cash Flow is available for variable dividends, debt or share repurchases, strategic acquisitions or other growth opportunities, or other discretionary expenditures, since we have mandatory debt service requirements and other non-discretionary expenditures that are not deducted from this measure.

We define Adjusted Net Income (Loss) as net income (loss) adjusted for derivative gains or losses net of cash received or paid for scheduled derivative settlements, unusual and infrequent items, and the income tax expense or benefit of these adjustments using our statutory tax rate. Adjusted Net Income (Loss) excludes the impact of unusual and infrequent items affecting earnings that vary widely and unpredictably, including non-cash items such as derivative gains and losses. This measure is used by management when comparing results period over period. We believe Adjusted Net Income (Loss) is useful to investors because it reflects how management evaluates the Company’s ongoing financial and operating performance from period-to-period after removing certain transactions and activities that affect comparability of the metrics and are not reflective of the Company’s core operations. We believe this also makes it easier for investors to compare our period-to-period results with our peers.

We define Adjusted General and Administrative Expenses as general and administrative expenses adjusted for non-cash stock compensation expense and unusual and infrequent costs. Management believes Adjusted General and Administrative Expenses is useful because it allows us to more effectively compare our performance from period to period. We believe Adjusted General and Administrative Expenses is useful to investors because it reflects how management evaluates the Company’s ongoing general and administrative expenses from period-to-period after removing non-cash stock compensation, as well as unusual or infrequent costs that affect comparability of the metrics and are not reflective of the Company’s administrative costs. We believe this also makes it easier for investors to compare our period-to-period results with our peers.

While Adjusted EBITDA, Adjusted Free Cash Flow, Adjusted Net Income (Loss) and Adjusted General and Administrative Expenses are non-GAAP measures, the amounts included in the calculation of Adjusted EBITDA, Adjusted Free Cash Flow, Adjusted Net Income (Loss) and Adjusted General and Administrative Expenses were computed in accordance with GAAP. These measures are provided in addition to, and not as an alternative for, income and liquidity measures calculated in accordance with GAAP and should not be considered as an alternative to, or more meaningful than income and liquidity measures calculated in accordance with GAAP. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing our financial performance, such as our cost of capital and tax structure, as well as the historic cost of depreciable and depletable assets. Our computations of Adjusted EBITDA, Adjusted Free Cash Flow, Adjusted Net Income (Loss) and Adjusted General and Administrative Expenses may not be comparable to other similarly titled measures used by other companies. Adjusted EBITDA, Adjusted Free Cash Flow, Adjusted Net Income (Loss) and Adjusted General and Administrative Expenses should be read in conjunction with the information contained in our financial statements prepared in accordance with GAAP.

ADJUSTED EBITDA

The following tables present reconciliations of the GAAP financial measures of net income (loss) and net cash provided (used) by operating activities to the non-GAAP financial measure of Adjusted EBITDA, as applicable, for each of the periods indicated.

	Three Months Ended
	June 30, 2024				March 31, 2024				June 30, 2023
	(unaudited)(in thousands)
Adjusted EBITDA reconciliation:
Net (loss) income	$	(8,769	)		$	(40,084	)		$	25,770
Add (Subtract):
Interest expense		10,050				9,140				8,794
Income tax (benefit) expense		(3,326	)			(13,900	)			10,616
Depreciation, depletion, and amortization		42,843				42,831				39,755
Impairment of oil and gas properties		43,980				—				—
Losses (gains) on derivatives		8,486				75,681				(6,847	)
Net cash (paid) for scheduled derivative settlements		(19,115	)			(9,094	)			(12,524	)
Other operating (income)		(3,204	)			(133	)			(1,033	)
Stock compensation expense(1)		1,990				385				3,552
Acquisition costs(2)		1,394				2,617				972
Non-recurring costs(3)		—				1,091				—
Adjusted EBITDA	$	74,329			$	68,534			$	69,055
Net cash provided by operating activities	$	70,891			$	27,273			$	62,538
Add (Subtract):
Cash interest payments		1,395				15,256				1,004
Cash income tax payments		491				—				670
Acquisition costs(2)		1,394				2,617				—
Non-recurring costs(3)		—				1,091				—
Changes in operating assets and liabilities - working capital(4)		3,293				22,543				6,065
Other operating (income) - cash portion(5)		(3,135	)			(246	)			(1,222	)
Adjusted EBITDA	$	74,329			$	68,534			$	69,055

__________(1) Decrease in the first quarter of 2024 is the result of stock award forfeitures.(2) Includes legal and other professional expenses related to various transactions activities.(3) In 2024, non-recurring costs included workforce reduction costs in the first quarter.(4) Changes in other assets and liabilities consists of working capital and various immaterial items.(5) Represents the cash portion of other operating (income) from the income statement, net of the non-cash portion in the cash flow statement.

ADJUSTED FREE CASH FLOW

The following table presents a reconciliation of the GAAP financial measure of operating cash flow to the non-GAAP financial measure of Adjusted Free Cash Flow for each of the periods indicated. We use Adjusted Free Cash Flow for our shareholder return model.

	Three Months Ended
	June 30, 2024				March 31, 2024				June 30, 2023
	(unaudited)(in thousands)
Adjusted Free Cash Flow reconciliation:
Net cash provided by operating activities(1)	$	70,891			$	27,273			$	62,538
Subtract:
Capital expenditures(2)		(42,325	)			(16,936	)			(19,625	)
Fixed dividends(3)		(9,233	)			(9,233	)			(9,139	)
Adjusted Free Cash Flow	$	19,333			$	1,104			$	33,774

__________(1) On a consolidated basis.(2) In 2024, we updated Adjusted Free Cash Flow to include all capital expenditures in the calculation of Adjusted Free Cash Flow. This update better aligns with the full capital expenditure requirements of the Company. In 2023, the definition of capital expenditures was the required amount to keep annual production essentially flat (maintenance capital), calculated as the capital expenditures for the E&P business for the periods presented. We did not retrospectively adjust 2023.

	Three Months Ended
	June 30, 2023
	(unaudited)(in thousands)
Consolidated capital expenditures(a)	$	(21,895	)
Excluded items(b)		2,270
Maintenance capital	$	(19,625	)

__________(a) Capital expenditures include capitalized overhead and interest and excludes acquisitions and asset retirement spending.(b) Comprised of the capital expenditures in our E&P segment that are related to strategic business expansion, such as acquisitions of oil and gas properties and any exploration and development activities to increase production beyond the prior year’s annual production volumes and capital expenditures in our well servicing and abandonment segment and corporate expenditures that are related to ancillary sustainability initiatives or other expenditures that are discretionary and unrelated to maintenance of our core business. For the three months ended June 30, 2023, we excluded approximately $1.3 million of capital expenditures related to our well servicing and abandonment segment, which was substantially all used for sustainability initiatives or other expenditures that are discretionary and unrelated to maintenance of our core business. For the three months ended June 30, 2023, we excluded approximately $0.9 million of corporate capital expenditures, which we determined was not related to the maintenance of our baseline production.

(3) Represents fixed dividends declared for the periods presented.

ADJUSTED NET INCOME (LOSS)

The following table presents a reconciliation of the GAAP financial measures of net income (loss) and net income (loss) per share — diluted to the non-GAAP financial measures of Adjusted Net Income (Loss) and Adjusted Net Income (Loss) per share — diluted for each of the periods indicated.

	Three Months Ended
	June 30, 2024								March 31, 2024								June 30, 2023
	(in thousands)				per share - diluted				(in thousands)				per share - diluted				(in thousands)				per share - diluted
	(unaudited)
Adjusted Net Income (Loss) reconciliation:
Net (loss) income	$	(8,769	)		$	(0.11	)		$	(40,084	)		$	(0.52	)		$	25,770			$	0.33
Add (Subtract):
Losses (gains) on derivatives		8,486				0.11				75,681				0.98				(6,847	)			(0.09	)
Net cash (paid) for scheduled derivative settlements		(19,115	)			(0.25	)			(9,094	)			(0.12	)			(12,524	)			(0.16	)
Other operating (income)		(3,204	)			(0.05	)			(133	)			—				(1,033	)			(0.01	)
Impairment of oil and gas properties		43,980				0.57				—				—				—				—
Acquisition costs(1)		1,394				0.02				2,617				0.03				972				0.01
Non-recurring costs(2)		—				—				1,091				0.02				—				—
Total additions (subtractions), net		31,541				0.40				70,162				0.91				(19,432	)			(0.25	)
Income tax (benefit) expense of adjustments(3)		(8,617	)			(0.11	)			(19,168	)			(0.25	)			5,328				0.07
Adjusted Net Income	$	14,155			$	0.18			$	10,910			$	0.14			$	11,666			$	0.15
Basic EPS on Adjusted Net Income	$	0.18							$	0.14							$	0.15
Diluted EPS on Adjusted Net Income	$	0.18							$	0.14							$	0.15
Weighted average shares of common stock outstanding - basic		76,939								76,254								76,721
Weighted average shares of common stock outstanding - diluted		77,161								77,373								79,285

__________(1) Includes legal and other professional expenses related to various transactions activities.(2) In 2024, non-recurring costs included workforce reduction costs in the first quarter.(3) The federal and state statutory rates were utilized for all periods presented.

ADJUSTED GENERAL AND ADMINISTRATIVE EXPENSES

The following table presents a reconciliation of the GAAP financial measure of general and administrative expenses to the non-GAAP financial measure of Adjusted General and Administrative Expenses for each of the periods indicated.

	Three Months Ended
	June 30, 2024				March 31, 2024				June 30, 2023
	(unaudited)($ in thousands)
Adjusted General and Administrative Expense reconciliation:
General and administrative expenses	$	18,881			$	20,234			$	22,488
Subtract:
Non-cash stock compensation expense (G&A portion)(1)		(1,843	)			(200	)			(3,379	)
Non-recurring costs(2)		—				(1,091	)			—
Adjusted General and Administrative Expenses	$	17,038			$	18,943			$	19,109
Well servicing and abandonment segment	$	2,454			$	2,929			$	2,958
E&P segment, and corporate	$	14,584			$	16,014			$	16,151
E&P segment, and corporate ($/boe)	$	6.34			$	6.93			$	6.84
Total mboe		2,300				2,310				2,361

__________(1) Decrease in the first quarter of 2024 is the result of stock award forfeitures.(2) In 2024, non-recurring costs included workforce reduction costs in the first quarter.

Contact

Contact: Berry Corporation (bry)
Todd Crabtree - Director, Investor Relations
(661) 616-3811
ir@bry.com